Automatic adjustment of NMR pulse sequence to optimize SNR based on real time analysis

ABSTRACT

Data from a string of multiple formation evaluation data sensor are evaluated by an expert system. Based on the analysis, the logging speed is increased if all the sensors justify it, and is reduced if any of the sensors require a reduced logging speed. Alternatively, the sensitive volume of a NMR sensor is altered based on a determination of a fraction of the sensitive volume that includes a borehole fluid. It is emphasized that this abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

CROSS REFERENCES TO RELATED APPLICATIONS

This is a divisional application of U.S. patent application Ser. No.11/179,990, filed on Jul. 12, 2005. U.S. patent application Ser. No.11/179,990 is a continuation-in-part of U.S. patent application Ser. No.10/819,665, filed on Apr. 7, 2004 (now U.S. Pat. No. 7,117,733) and isalso a continuation-in-part of U.S. patent application Ser. No.10/828,812 filed on Apr. 21, 2004 (now U.S. Pat. No. 7,193,414) which isa continuation of U.S. patent application Ser. No. 09/928,768 filed onAug. 13, 2001 which has issued as U.S. Pat. No. 6,727,696.

FIELD OF THE INVENTION

This invention relates generally to methods of improved logging usingoilfield borehole tools and more particularly to dynamic adjustment ofthe logging speed and acquisition parameters based on the quality of theacquired data and the formations being evaluated.

BACKGROUND OF THE ART

Oil or gas wells are often surveyed to determine one or more geological,petrophysical, geophysical, and well production properties (“parametersof interest”) using electronic measuring instruments conveyed into theborehole by an umbilical such as a cable, a wireline, slickline, drillpipe or coiled tubing. Tools adapted to perform such surveys arecommonly referred to as formation evaluation tools. These tools useelectrical, acoustical, nuclear and/or magnetic energy to stimulate theformations and fluids within the borehole and measure the response ofthe formations and fluids. The measurements made by downhole instrumentsare transmitted back to the surface. In many instances, multiple tripsor logging runs are needed to collect the necessary data. Additionally,the logging speed is usually a predetermined fixed quantity.

In order to reduce the amount of rig time needed for wireline logging,it is common practice to run multiple sensors in a single run. FOCUS™,from Baker Atlas Inc., is an open hole logging systems suitable for usewith the present invention. All of the downhole instruments have beenredesigned, incorporating advanced downhole sensor technology, intoshorter, lighter, more reliable logging instruments, capable ofproviding formation evaluation measurements with the same precision andaccuracy as the industry's highest quality sensors, at much higherlogging speeds. Logging speeds are up to twice the speed of conventionaltriple-combo and quad combo logging tool strings. Speeds of up to 3600ft/hr (1080 m/min) are possible. The logging system may include fourstandard major open hole measurements (resistivity, density, neutron,acoustic) plus auxiliary services.

The resolution and accuracy of logging measurements is determined by thetype of measurement and the type of formation being logged. Themeasurement may be tailored to the type of formation. For example, U.S.Pat. No. 5,309,098 to Coates et al. teaches a method and apparatus inwhich a variable time-window echo-recording system is used to obtainsignificant improvements in signal quality and logging speed for NMRmeasurements. An initial test is performed to provide an assessment ofthe relaxation qualities of the sample. If the test reveals that thesample is a slow-relaxation rock, then the full time is allocated tomeasuring echoes. However, if the test reveals that the sample is a fastdecay rock, then the echo acquisition time window is reduced. Thisprovides increased efficiency since the system is able to maximize thenumber of measurements made by optimizing the individual samplingintervals to the particular geologic structure being tested.

Generally, prior art methods have conducted logging at a uniform loggingspeed. A fixed logging speed is used for the entire logging interval.This flies in the face of logic since reservoir intervals form only asmall portion of the entire geologic section and it is only in reservoirintervals is it necessary to get precise and accurate measurements withhigh resolution: in the non-reservoir intervals, high precision andaccuracy are not usually necessary.

It would be desirable to have a method and apparatus of logging aborehole in which the inefficiencies of the prior art are overcome. Suchan invention should preferably be able to accommodate a variety oflogging tools. The present invention satisfies this need.

SUMMARY OF THE INVENTION

One embodiment of the invention is a method of conducting loggingoperations of a borehole in an earth formation. A plurality of formationevaluation (FE) sensors are conveyed into the borehole using aconveyance device. The conveyance device is used to move the pluralityof FE sensors at a logging speed while making measurements with the FEsensors. An expert system is used for analyzing said measurements madeby the FE sensors. A signal for alteration of the logging speed isprovided based on the analysis. The sensors may include a resistivitysensor, a natural gamma ray sensor, a porosity sensor, a density sensor,a nuclear magnetic resonance sensor and/or an acoustic sensor. Theconveyance device may be a wireline or a slickline. The logging speedmay be altered based on the provided signal. In addition, a wait timefor NMR signal acquisition, and/or the number of echoes acquired in NMRsignal acquisition may be altered. The signal to alter may be based on adetermination of a spin relaxation time and/or an identification of abed boundary.

Another embodiment of the invention is an apparatus for conductinglogging operations of a borehole in an earth formation. The apparatusincludes a plurality of formation evaluation (FE) sensors, a conveyancewhich moves the plurality of FE sensors at a logging speed while makingmeasurements with said FE sensors, a processor including an expertsystem which analyzes the measurements made by the FE sensors, and aprocessor which provides a signal for alteration of the logging speedbased on the analysis. At least one of the processors is at a downholelocation. The FE sensors may include a resistivity sensor, a naturalgamma ray sensor, a porosity sensor, a density sensor, a nuclearmagnetic resonance sensor, and/or an acoustic sensor. The conveyancedevice may be a wireline or a slickline. The apparatus may furtherinclude a device which positions one of the FE sensors at a differentdistance from the borehole wall than the distance of another of the FEsensors from the borehole wall.

Another embodiment of the invention is a method of conducting loggingoperations of a borehole in an earth formation in which a nuclearmagnetic resonance (NMR) sensor is conveyed into the borehole on aconveyance device. A fraction of at least one sensitive volume of theNMR sensor that includes borehole fluid is determined. The sensitivevolume is altered based on the determination. There may be a pluralityof sensitive volumes from which NMR signals are obtained, thedetermination being based on the NMR signals from the plurality ofsensitive volumes. The determination may also be made based on astandoff measurement. Altering the sensitive volume may be done byaltering a frequency of operation of the NMR tool, altering a standoffdistance of the tool, using a field shifting magnet and/or altering adistance of the sensitive volume from the borehole wall. An additionalsensor responsive to a property of the formation may be used and thelogging speed altered based on analysis of outputs of the additionalsensor and the NMR sensor.

Another embodiment of the invention is an apparatus for conductinglogging operations of a borehole in an earth formation. The apparatusincludes a conveyance device which conveys a nuclear magnetic resonance(NMR) sensor into the borehole, and a processor. The processordetermines a fraction of at least one sensitive volume of the NMR sensorincluding a borehole fluid, and alters the at least one sensitive volumebased on the determination. The NMR sensor may have a plurality ofsensitive volumes from which NMR signals are obtained. The processor maymake the determination based on the NMR signals from the plurality ofsensitive volumes. The processor may alter the sensitive volume bychanging a frequency of operation of the NMR sensor and/or by activatinga field shifting magnet. The apparatus may include a caliper whichdetermines a standoff of the NMR sensor and the processor may make thedetermination base don the standoff. The caliper may be an acousticcaliper or a mechanical caliper. The apparatus may include a device thatalters the sensitive volume by changing the position of the NMR sensorinside the borehole. The apparatus may include at least one additionalformation evaluation sensor and the processor may alter the loggingspeed based on the outputs of the NMR sensor and the at least oneadditional sensor.

Another embodiment of the invention is a machine readable medium for usewith an apparatus for conducting logging operations of a borehole in anearth formation. The apparatus includes a conveyance device whichconveys a nuclear magnetic resonance (NMR) sensor into the borehole. Themedium includes instructions which enable determination of a fraction ofat least one sensitive volume of the NMR sensor including a boreholefluid and altering the at least one sensitive volume based on thedetermination. The medium may be a ROM, an EPROM, an EEPROM, a FlashMemory and/or an Optical disk.

BRIEF DESCRIPTION OF THE DRAWINGS

For detailed understanding of the present invention, reference should bemade to the following detailed description of the preferred embodiment,taken in conjunction with the accompanying drawing and in which:

FIG. 1 (prior art) is a schematic illustration of a wireline loggingsystem including a plurality of sensors;

FIG. 2 (prior art) is an embodiment of a system using a radiallyadjustable module adapted for use in logging operations;

FIG. 3 (prior art) illustrates a sectional view of one embodiment of apositioning device made in accordance with the present invention;

FIG. 4 (prior art) is a schematic elevation view of radially adjustablemodule positioned in an open hole portion of a borehole;

FIG. 5 is a schematic illustration of steps involved in the method ofthe present invention;

FIGS. 6 a and 6 b show the alteration of the sensitive volume bymovement of the tool within the borehole; and

FIGS. 7 a and 7 b show alteration of the sensitive volume by use of afield shifting magnet and/or altering the frequency of operation.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is discussed with reference to specific logginginstruments that may form part of a string of several logginginstruments for conducting wireline logging operations. It is to beunderstood that the choice of the specific instruments discussed hereinis not to be construed as a limitation and that the method of thepresent invention may also be used with other logging instruments aswell.

A typical configuration of the logging system is shown in FIG. 1. Thisis a modification of an arrangement from U.S. Pat. No. 4,953,399 toFertl et al. having the same assignee as the present invention and thecontents of which are incorporated herein by reference. Shown in FIG. 1is a suite of logging instruments 10, disposed within a borehole 11penetrating an earth formation 13, illustrated in vertical section, andcoupled to equipment at the earth's surface in accordance with themethod and apparatus for determining characteristics of clay-bearingformations of the present invention. Logging instrument suite 10 mayinclude a resistivity device 12, a natural gamma ray device 14, and twoporosity-determining devices, such as a neutron device 16 and a densitydevice 18. Collectively, these devices and others used in the boreholefor logging operations are referred to as formation evaluation sensors.Resistivity device 12 may be one of a number of different types ofinstruments known to the art for measuring the electrical resistivity offormations surrounding a borehole so long as such device has arelatively deep depth of investigation. For example, a HDIL (HighDefinition Induction Logging) device such as that described in U.S. Pat.No. 5,452,761 to Beard et al. having the same assignee as the presentinvention and the contents of which are fully incorporated herein byreference may be used. Natural gamma ray device 14 may be of a typeincluding a scintillation detector including a scintillation crystalcooperatively coupled to a photomultiplier tube such that when thecrystal is impinged by gamma rays a succession of electrical pulses isgenerated, such pulses having a magnitude proportional to the energy ofthe impinging gamma rays. Neutron device 16 may be one of several typesknown to the art for using the response characteristics of the formationto neutron radiation to determine formation porosity. Such a device isessentially responsive to the neutron moderating properties of theformation. Density device 18 may be a conventional gamma-gamma densityinstrument such as that described in U.S. Pat. No. 3,321,625 to Wahl,used to determine the bulk density of the formation. A downholeprocessor may be provided at a suitable location as part of theinstrument suite.

Instrument suite 10 is conveyed within borehole 11 by a cable 20containing electrical conductors (not illustrated) for communicatingelectrical signals between instrument suite 10 and the surfaceelectronics, indicated generally at 22, located at the earth's surface.Logging devices 12, 14, 16 and 18 within instrument suite 10 arecooperatively coupled such that electrical signals may be communicatedbetween each device 12, 14, 16 and 18 and surface electronics 22. Cable20 is attached to a drum 24 at the earth's surface in a manner familiarto the art. Instrument suite 10 is caused to traverse borehole 11 byspooling cable 20 on to or off of drum 24, also in a manner familiar tothe art.

Surface electronics 22 may include such electronic circuitry as isnecessary to operate devices 12, 14, 16 and 18 within instrument suite10 and to process the data therefrom. Some of the processing may be donedownhole. In particular, the processing needed for making decisions onspeeding up (discussed below) for slowing down the logging speed ispreferably down downhole. If such processing is done downhole, thentelemetry of instructions to speed up or slow down the logging could becarried out substantially in real time. This avoids potential delaysthat could occur if large quantities of data were to be telemetereduphole for the processing needed to make the decisions to alter thelogging speed. It should be noted that with sufficiently fastcommunication rates, it makes no difference where the decision making iscarried out. However, with present data rates available on wirelines,the decision making is preferably done downhole.

Control circuitry 26 contains such power supplies as are required foroperation of the chosen embodiments of logging devices within instrumentsuite 10 and further contains such electronic circuitry as is necessaryto process and normalize the signals from such devices 12, 14, 16 and 18in a conventional manner to yield generally continuous records, or logs,of data pertaining to the formations surrounding borehole 11. These logsmay then be electronically stored in data storage 32 prior to furtherprocessing. The processor 28 includes the ability, such as thatdescribed in U.S. Pat. No. 4,271,356 to Groeschel et al, for separatingradiation measurements from natural gamma ray device 14 into individualenergy bands centered about energy peaks of selected elemental sourcesof radiation, preferably the energy peaks of potassium, uranium andthorium. This processing of the natural gamma ray device could also bedone by the downhole processor.

Surface electronics 22 may also include such equipment as willfacilitate machine implementation of the method of the presentinvention. Processor 28 may be of various forms but preferably is anappropriate digital computer programmed to process data from loggingdevices 12, 14, 16 and 18. Memory unit 30 and data storage unit 32 areeach of a type to cooperatively interface with processor 28 and/orcontrol circuitry 26. Depth controller 34 determines the longitudinalmovement of instrument suite 20 with borehole 11 and communicates asignal representative of such movement to processor 28. The loggingspeed is altered in accordance with speedup or slowdown signals that maybe communicated from the downhole processor, or provided by the surfaceprocessor, as discussed below. This is done by altering the rotationspeed of the drum 24. Offsite communication may be provided, for exampleby a satellite link, by the telemetry unit 36.

While running different logging instruments in a single wireline run,the present invention may use a configuration disclosed in U.S. Pat. No.7,045,737 to Frost et al. The teachings of Frost recognize the fact thatdifferent logging instruments operate best at different standoffs fromthe borehole wall.

Referring next to FIG. 2, there is shown a rig 10 on the surface that ispositioned over a subterranean formation of interest. The rig 10 can bea part of a land or offshore a well production/construction facility. Aborehole formed below the rig 10 includes a cased portion 42 and an openhole portion 11. In certain instances (e.g., during drilling,completion, work-over, etc.), a logging operation is conducted tocollect information relating to the formation and the borehole.Typically, a tool system 100 is conveyed downhole via a wireline 20 tomeasure one or more parameters of interest relating to the boreholeand/or the formation 13. The term “wireline” as used hereinafterincludes a cable, a wireline, as well as a slickline. The tool system100 can include an instrument suite comprising one or more modules 102a, b, each of which has a tool or a plurality of tools 104 a, b, adaptedto perform one or more downhole tasks. The term “module” should beunderstood to be a device such as a sonde or sub that is suited toenclose, house, or otherwise support a device that is to be deployedinto a borehole. While two proximally positioned modules 102 a, b andtwo associated tools 104 a, b, are shown, it should be understood that agreater or fewer number may be used.

In one embodiment, the tool 104 a is a formation evaluation sensoradapted to measure one or more parameters of interest relating to theformation or borehole. It should be understood that the term formationevaluation sensor encompasses measurement devices, sensors, and otherlike devices that, actively or passively, collect data about the variouscharacteristics of the formation, directional sensors for providinginformation about the tool orientation and direction of movement,formation testing sensors for providing information about thecharacteristics of the reservoir fluid and for evaluating the reservoirconditions. The formation evaluation sensors may include resistivitysensors for determining the formation resistivity, dielectric constantand the presence or absence of hydrocarbons, acoustic sensors fordetermining the acoustic porosity of the formation and the bed boundaryin formation, nuclear sensors for determining the formation density,nuclear porosity and certain rock characteristics, nuclear magneticresonance sensors for determining the porosity and other petrophysicalcharacteristics of the formation. The direction and position sensorspreferably include a combination of one or more accelerometers and oneor more gyroscopes or magnetometers. The accelerometers preferablyprovide measurements along three axes. The formation testing sensorscollect formation fluid samples and determine the properties of theformation fluid, which include physical properties and chemicalproperties. Pressure measurements of the formation provide informationabout the reservoir characteristics.

The tool system 100 can include telemetry equipment 150, a local ordownhole controller 152 and a downhole power supply 154. The telemetryequipment 150 provides two-way communication for exchanging data signalsbetween a surface controller 112 and the tool system 100 as well as fortransmitting control signals from the surface processor 112 to the toolsystem 100.

In an exemplary arrangement, and not by way of limitation, a firstmodule 102 a includes a tool 104 a configured to measure a firstparameter of interest and a second module 102 b includes a tool 104 bthat is configured to measure a second parameter of interest that iseither the same as or different from the first parameter of interest. Inorder to execute their assigned tasks, tools 104 a and 104 b may need tobe in different positions. The positions can be with reference to anobject such as a borehole, borehole wall, and/or other proximallypositioned tooling. Also, the term “position” is meant to encompass aradial position, inclination, and azimuthal orientation. Merely forconvenience, the longitudinal axis of the borehole (“borehole axis”)will be used as a reference axis to describe the relative radialpositioning of the tools 104 a, b. Other objects or points can also beused as a reference frame against which movement or position can bedescribed. Moreover, in certain instances, the tasks of the tools 104 a,b can change during a borehole-related operation. Generally speaking,tool 104 a can be adapted to execute a selected task based on one ormore selected factors. These factors can include, but not limited to,depth, time, changes in formation characteristics, and the changes intasks of other tools.

Modules 102 a and 102 b may each be provided with positioning devices140 a, 140 b, respectively. The positioning device 140 is configured tomaintain a module 102 at a selected radial position relative to areference position (e.g., borehole axis). The position device 140 alsoadjusts the radial position of module 102 upon receiving a surfacecommand signal and/or automatically in a closed-loop type manner. Thisselected radial position is maintained or adjusted independently of theradial position(s) of an adjacent downhole device (e.g., measurementtools, sonde, module, sub, or other like equipment). An articulatedmember, such a flexible joint 156 which couples the module 102 to thetool system 100 provides a degree of bending or pivoting to accommodatethe radial positioning differences between adjacent modules and/or otherequipment (for example a processor sonde or other equipment). In otherembodiments, one or more of the positioning devices has fixedpositioning members.

The positioning device 140 may include a body 142 having a plurality ofpositioning members 144(a, b, c) circumferentially disposed in aspace-apart relation around the body 142. The members 144(a, b, c) areadapted to independently move between an extended position and aretracted position. The extended position can be either a fixed distanceor an adjustable distance. Suitable positioning members 144(a, b, c)include ribs, pads, pistons, cams, inflatable bladders or other devicesadapted to engage a surface such as a borehole wall or casing interior.In certain embodiments, the positioning members 144(a, b, c) can beconfigured to temporarily lock or anchor the tool in a fixed positionrelative to the borehole and/or allow the tool to move along theborehole.

Drive assemblies 146(a, b, c) are used to move the members 144(a, b, c).Exemplary embodiments of drive assemblies 146(a, b, c) include anelectro-mechanical system (e.g., an electric motor coupled to amechanical linkage), a hydraulically-driven system (e.g., apiston-cylinder arrangement fed with pressurized fluid), or othersuitable system for moving the members 144(a, b, c) between the extendedand retracted positions. The drive assemblies 146(a, b, c) and themembers 144(a, b, c) can be configured to provide a fixed or adjustableamount of force against the borehole wall. For instance, in apositioning mode, actuation of the drive assemblies 146(a, b, c) canposition the tool in a selected radial alignment or position. The forceapplied to the borehole wall, however, is not so great as to prevent thetool from being moved along the borehole. In a locking mode, actuationof the drive assembly 146(a, b, c) can produce a sufficiently highfrictional force between the members 144(a, b, c) and the borehole wallas to prevent substantial relative movement. In certain embodiments, abiasing member (not shown) can be used to maintain the positioningmembers 144(a, b, c) in a pre-determined reference position. In oneexemplary configuration, the biasing member (not shown) maintains thepositioning member 144(a, b, c) in the extended position, which wouldprovide centralized positioning for the module. In this configuration,energizing the drive assembly overcomes the biasing force of the biasingmember and moves one or more of the positioning members into a specifiedradial position, which would provide decentralized positioning for themodule. In another exemplary configuration, the biasing member canmaintain the positioning members in a retracted state within the housingof the positioning device. It will be seen that such an arrangement willreduce the cross sectional profile of the module and, for example, lowerthe risk that the module gets stuck in a restriction in the borehole.

The positioning device 140 and drive assembly 146(a, b, c) can beenergized by a downhole power supply (e.g., a battery or closed-loophydraulic fluid supply) or a surface power source that transmits anenergy stream (e.g., electricity or pressurized fluid) via a suitableconduit, such as the umbilical 120. Further, while one drive assembly(e.g., drive assembly 146 a) is shown paired with one positioning member144 (e.g., position member 144 a), other embodiments can use one driveassembly to move two or more positioning members.

Referring now to FIG. 4 there is shown an exemplary formation evaluationtool system 200 disposed in an open hole section 11. The tool system 200includes a plurality of modules or subs for measuring parameters ofinterest. An exemplary module 202 is shown coupled to an upper toolsection 204 and a lower tool section 206 by a flexible member 156. Inone exemplary embodiment, the module 202 supports an NMR tool 208. Asdiscussed in U.S. Pat. No. 6,525,535 to Reiderman et al., depending uponthe size of the borehole, the NMR tool may be operated in either acentralized manner or in an eccentric manner. In the open hole 18, theacoustic tool 208 may be set in a decentralized position (i.e., radiallyeccentric position) by actuating the positioning members 140 a and 140b. This decentralized or radially offset position is substantiallyindependent of the radial positions of the downhole device (e.g.,measurement devices and sensors) along or in the upper/lower tool stringsection 204 and 206. That is, the upper or tool string section 204 and206 can have formation evaluation sensors and measurement devices thatare in a radial position that is different from that of the module 202.In this decentralized or radially offset position, the NMR tool can beused to gather data in large diameter boreholes. In a small diameterborehole, the NMR tool may be operated in a central position of theborehole. It should be appreciated that such motion can be accomplishedby sequentially varying the distance of extension/retraction of thepositioning members.

Referring next to FIG. 5, a flow chart generally illustrating the methodof the present invention is shown. The downhole tool system is operatingat an initial logging speed 301. The initial logging speed may bedetermined based on prior knowledge of the expected geologic formationsand fluids. Measurements are made with a plurality of formationevaluation sensors. To simplify the illustration, only two such FEsensors depicted by 303 and 305 are shown. In actual practice, there maybe more than two FE sensors in the logging system. As will be discussedlater, the signals measured by the sensor 305 are analyzed by aprocessor, preferably the downhole processor, to see if the data qualityare good enough to permit a speedup 323 of logging. The processing mayalso be done by a surface processor, or by both a surface processor anda downhole processor. Similarly, the signals measured by sensor 303 areanalyzed by a processor to see if the data quality are good enough topermit a speedup 333 of logging. The specific nature of the check isdiscussed below with reference to individual sensor types. Similarly,the measurements of sensor 303 are checked to see if a speedup iswarranted 333. If all the sensors provide a speedup signal 329, aspeedup signal is provided 321. Not shown in FIG. 4 is a check to makesure that all the speedup signals are valid. Possible situations inwhich a speedup signal may not be valid are discussed below.

Checks are also made to see if the sensor 305 would require a slowerlogging speed 327 with a similar check to see if the sensor 303 wouldrequire a slower logging speed 335. The specific nature of the check forslower logging speed is discussed later. If at least one of the sensorsprovide a valid slowdown signal 337, then logging is slowed down 331. Itshould further be noted that the order of performing the slowdown andspeedup evaluation in FIG. 4 is for illustrative purposes only, and theevaluation could be performed in the opposite order. An importantfeature of the invention is summarized in the following test:

-   1. If all the sensors provide a valid speedup signal, then logging    speed is increased;-   2. If one or more of the sensors provide a valid slowdown signal,    then logging speed is decreased; and-   3. If neither (1) nor (2) occurs, the logging speed is maintained.

The decision as to whether to speed up or slow down the logging may bebased on a comparison measurements made over several time intervals.With the natural gamma ray tool, a typical sampling rate is 10 ms. Witha logging speed of 1200 ft/hr, 100 samples are obtained every second,which corresponds to a distance of four inches. If the average and/orthe variance of measurements over say 1 second is substantially the sameas the average of measurements over 2 seconds, it is an indication thatlogging speed may be increased without loss of resolution of loss ofprecision. With the HDIL tool, for example, transmitter and receivercoils are configured to operate with different depths of investigationby operating at several frequencies and/or by using data from severaltransmitter-receiver spacings. There is a high degree of redundancy inthe data. Again, by comparing averages over different time intervals, anindication can be obtained as to whether logging speed may be increased,or, conversely, whether logging speed should be decreased.

With nuclear sensors such as used for neutron porosity or gamma raydensity logs, the count rates are subject to statistical fluctuations.This is due to the fact that over short time intervals, the source emitsradiation that may fluctuate, and furthermore, the interaction of thesource radiation with nuclei in the formation is also governed bystatistical processes. In order to make a meaningful determination ofporosity and/or density, it becomes important to make sure that theactual number of accumulated counts has a minimum value for all thedetectors used in making the nuclear measurements.

Another point to note with respect to nuclear sensors is that somecompensation is applied to account for offset of the detectors from theborehole wall. For example, if ρ_(ss) and ρ_(ls) are measurements madeby short spaced (SS) and long spaced (LS) sensors, a density correctionis applied to give a corrected density according to the relation:Δρ=ρ−ρ_(LS) =f(ρ_(LS)−ρ_(SS))  (1)This is called the “spine and rib” correction. In situations where thereare washouts, is possible that the individual sensor measurements maypass the tests described above regarding the count rate and thestatistical fluctuations. Nevertheless, corrected density measurementsmay still be invalid due to the large washout. This is an example of therequirement that the speedup or slowdown indicator (discussed above) bea valid one.

An acoustic sensor may also be part of the instrument suite. This isgenerally used at least for measurements of compressional (P-wave)velocities of earth formations. To make measurements of P-wavevelocities, the transmitter(s) and receivers that comprise the acousticsensor are operated in a monopole mode. Energy generated by thetransmitter travels through the formation as a refracted P-wave and fromtraveltime measurements at the array of receivers, the P-wave velocitycan be determined. The semblance of the received signal is an indicationof the quality of the data, and if the semblance is sufficiently high,then it is possible to increase the logging speed without detriment. Itshould be noted that if the formation shear wave (S-wave) velocity isgreater than the velocity of sound in the drilling mud, it is possibleto determine formation S-velocities using a monopole excitation.

The acoustic tool may also be operated in a dipole mode in which shearwaves (S-waves) are excited in the formation. Again, the semblance ofthe received signals may be used as an indicator for possible speedup oflogging speed. It should be noted that acoustic measurements takeseveral milliseconds to make, compared to the few microseconds neededfor nuclear and resistivity measurements. The acoustic tool may also beoperated in the so-called cross-dipole mode wherein the transmitter isactivated in a first dipole mode and then activated in a second dipolemode orthogonal to the first dipole mode. The cross-dipole mode isuseful in determining azimuthal anisotropy in the earth formation, anindication of possible fracturing. It should be clear that with respectto the acoustic tool, the speedup or slowdown indicator is based on allof the modes of acquisition that are desired.

For logging in laminated reservoirs (that have transverse isotropy inboth resistivity and acoustic properties), a multicomponent resistivitysensor may be included in the instrument suite. Service with such asensor is provided by Baker Hughes Incorporated under the mark 3DEX^(SM)and a tool suitable for the purpose is disclosed in U.S. Pat. No.6,147,496 to Strack et al. Using such a device, it is possible todetermine resistivity anisotropy in the earth formation that is a betterindication of reservoir quality than the HDIL measurements (that aresensitive only to horizontal resistivity). In anisotropic reservoirs, itmay also be desirable to operate the acoustic sensor in the dipole mode.The natural gamma ray sensors do not necessarily have the resolution tobe able to identify laminations at the scale at which resistivity and/oracoustic anisotropy may occur. Consequently, it may be desirable toinclude a high resolution resistivity sensor, such as a microlaterolog,as part of the instrument suite. Signals from such a sensor could beused to start acquisition with the 3DEX device and/or to switch theacoustic sensor to joint monopole/dipole operation.

In one embodiment of the invention, a processor including an expertsystem analyzes the output of the FE sensors. The processor that doesthe analysis may be a downhole processor or a surface processor. Theexpert system determines the lithology of the formation being logged anda speedup or slowdown signal may be provided based on the determinelithology. For example, in shale formations where high resolution anddetailed NMR spin relaxation information is not necessary and the NMRspin-lattice relaxation time is short, a speedup signal may be provided.If a microresistivity log indicates a laminated formation, a slowdownsignal may be provided to enable accurate 3DEX measurements.

U.S. Pat. No. 7,193,414 to Kruspe et al., having the same assignee asthe present application and the contents of which are fully incorporatedherein by reference, discloses the use of an expert system as part of aprocessor that uses the output of FE sensors to determine lithology.

Specifically, gamma rays measurements may be used to determine the shalecontent of the formation at the depth of the NMR sensors. In a shalyinterval, short pulse sequences and small values of ΔTE are sufficient.The presence of hydrocarbons in the formation is diagnosed fromresistivity measurements. The presence of gas in the formation may beindicated by acoustic log measurements. As would be known to thoseversed in the art, even a small amount of gas in the formationsignificantly lowers the P-wave velocity in a porous sand formation andadditional changes in P-wave velocity changes are only slightly affectedby the amount of gas present. In such a situation, it is desirable touse a dual wait time acquisition and processing to determine the gassaturation.

The Expert System is preferably implemented using neural networks (NNs).In one embodiment of the invention, more than one NN is used. A first NNis used for determination of lithology and formation fluid type from FEmeasurements. A second NN may be used for modifying the acquisition andprocessing parameters based upon the knowledge of the lithology andfluid type and the drilling conditions.

In one embodiment of the present invention, acquisition of data using anNMR tool is dynamically altered. U.S. Pat. No. 5,309,098 to Coatesteaches an arrangement in which an initial test is performed todetermine the relaxation characteristics of the formation being tested.This information obtained from this initial test is then used to selecta sampling interval which optimizes the collection of data for theparticular pore structure of the formation being tested. The NMR tooldisclosed in Coates is a single frequency tool such as that described inU.S. Pat. No. 3,213,357 to Brown et al.

One of the problems with NMR tools is the possibility of the sensitivevolume extending into the borehole. In such a situation, the NMR signalsfrom the borehole fluid will dominate the signals from the formation,rendering the results incorrect. In one embodiment of the presentinvention, a test is performed at intervals that may be determined inmany ways. For example, standoff measurements made by a caliper may beused to detect washouts. From the standoff measurements, U.S. Pat. No.6,603,310 to Georgi et al., having the same assignee as the presentapplication and the contents of which are fully incorporated herein byreference, teaches the determination of the fraction of the sensitivevolume that includes borehole fluid and correcting the NMR signals forthe contamination. In the present invention, the sensitive volume isaltered on the basis of the standoff measurements. This may be done inmany ways.

In one embodiment of the invention, the NMR tool may be used as part ofthe logging string of Frost discussed above with reference to FIGS. 2and 4. The standoff measurements may then be used by a processor tocontrol the movement of an eccentered tool towards or away from theborehole wall. This is illustrated with reference to FIGS. 6 a and 6 b.Shown in FIG. 6 a is a borehole 351 with a logging tool denoted by 353inside it. The sensitive volume is denoted by 355. The direction of thestatic magnetic field is given by 357. For the case shown in FIG. 6 a,the sensitive volume extends into the borehole. By moving the tool tothe position indicated by 353′ in FIG. 6 b, the sensitive volume 355′ iscompletely within the formation.

In another embodiment of the invention, a field shifting electromagnetmay be used to alter the distance from the tool for a given frequency ofoperation. When the field of the field-shifting magnet reinforces thestatic magnetic field of the permanent magnet, then for a givenfrequency of operation, the sensitive region is moved away from thetool. When the field of the field-shifting magnet opposes the staticmagnetic field of the permanent magnet, then for a given frequency ofoperation, the sensitive region is moved closer to the tool. Shown inFIG. 7 a is a case where the sensitive region 405 of the tool 403extends into the borehole 401. The direction of the static magneticfield is given by 407. By increasing the static magnetic field strengthusing the field shifting magnet, the sensitive volume 405′ in FIG. 7 bdoes not extend into the borehole 401′ for the same position of the tool403′.

Instead of using a field shifting magnet, the sensitive region can bechanged by altering the frequency of operation. Lowering the frequencymoves the sensitive region away from the tool while increasing thefrequency moves the sensitive region towards the tool. The principle forthis is the same as for the field shifting magnet shown in FIGS. 7 a and7 b. It should be noted that the example shown in FIGS. 7 a and 7 b arefor an eccentered tool having an arcuate region of examination. This isnot a limitation of the invention and the method could also be used fora centered tool within the borehole.

The discussion above with reference to FIGS. 6 a, 6 b, 7 a and 7 b dealtwith a examples in which a single sensitive region was altered. Themethod of dynamic alteration of the region of examination may also beused with a multifrequency logging tool such as that disclosed inReiderman. U.S. Pat. No. 7,227,355 to Chen et al. having the sameassignee as the present invention and the contents of which areincorporated herein by reference discloses a method for determining thefraction of each of a plurality of sensitive volumes that may beaffected by the presence of borehole fluid. This may be done without theuse of standoff measurements. Chen also teaches a method of correctingthe data to correct for the effects of borehole fluids. In the presentinvention, instead of correcting the data, alteration of the pluralityof sensitive volumes may be done using the methods discussed above.Alternatively, data from some of the sensitive volumes may be discarded.

The processing of the measurements made in wireline applications may bedone by the surface processor, the downhole processor or a remotelocation. The data acquisition may be controlled at least in part by thedownhole electronics. Implicit in the control and processing of the datais the use of a computer program on a suitable machine readable mediumthat enables the processors to perform the control and processing. Themachine readable medium may include ROMs, EPROMs, EEPROMs, FlashMemories and Optical disks.

As would be known to those versed in the art, wireline loggingoperations are typically conducted with the instrument suite beingpulled up the borehole. This is preferable to logging with theinstrument suite being lowered into the borehole since in the lattersituation, there may be sticking of the instrument suite into theborehole with the result that the logging depth as determined at thesurface location may not correspond to the actual depth of theinstruments. With the variations in logging speed that are possibleduring practice of the present invention, due to the elasticity of thewireline, there may be “yo-yoing” of the instrument suite at the bottomof the wireline. U.S. Pat. Nos. 6,154,704 and 6,256,587 to Jericevic etal., having the same assignee as the present application and thecontents of which are fully incorporated herein by reference, presentmethods for correcting the measurements for the effects of the yo-yoing.In the context of the present invention, this correction may be madeafter the logging operations are conducted on the stored data at thesurface. Alternatively, a correction may be applied downhole prior toany determination to speed up or slow down logging speed.

The present invention has been described in the context of a wirelinedevice. The method of the present invention is equally applicable onslickline conveyed device wherein a downhole processor is used forproviding a signal to speed up or slow down the speed. The slickline mayoptionally be conveyed inside a drilling tubular. The FE sensormeasurements are stored in a downhole memory for subsequent retrieval.

While the foregoing disclosure is directed to the preferred embodimentsof the invention, various modifications will be apparent to thoseskilled in the art. It is intended that all variations within the scopeof the appended claims be embraced by the foregoing disclosure.

1. A method of conducting logging operations in a borehole, the methodcomprising: (a) conveying at least one formation evaluation (FE) sensorinto the borehole; (b) using an expert system to analyze measurementsmade by the at least one FE sensor; and (c) altering a logging parameterbased on the analysis.
 2. The method of claim 1 wherein the at least oneFE sensor is selected from the group consisting of (i) a resistivitysensor, (ii) a natural gamma ray sensor, (iii) a porosity sensor, (iv) adensity sensor,(v) a nuclear magnetic resonance sensor, and, (vi) anacoustic sensor.
 3. The method of claim 1 further comprising conveyingthe at least one FE sensor into the borehole on a conveyance deviceselected from the group consisting of (i) a wireline, and, (ii) aslickline.
 4. The method of claim 1 wherein altering the loggingparameter is based on at least one of (i) a determination of a spinrelaxation time, (ii) an identification of a bed boundary.
 5. The methodof claim 1 wherein altering the logging parameter comprises altering alogging speed.
 6. The method of claim 5 wherein altering the loggingspeed further comprises at least one of (i) altering a wait time for NMRsignal acquisition, and (ii) altering the number of echoes acquired inNMR signal acquisition.
 7. An apparatus for conducting loggingoperations of a borehole in an earth formation, the apparatuscomprising: (a) at least one formation evaluation (FE) sensor; (b) anexpert system which analyzes the measurements made by the at least oneFE sensor; and (c) a processor which alters a logging parameter based onsaid analysis.
 8. The apparatus of claim 7 wherein at least one of the(i) the expert system, and (ii) the processor is at a downhole location.9. The apparatus of claim 7 wherein the at least one FE sensor isselected from the group consisting of (i) a resistivity sensor, (ii) anatural gamma ray sensor, (iii) a porosity sensor, (iv) a densitysensor,(v) a nuclear magnetic resonance sensor, and, (vi) an acousticsensor.
 10. The apparatus of claim 7 further comprising a conveyancedevice which conveys the at least one FE sensor into the borehole, theconveyance device is selected from the group consisting of (i) awireline, and (ii) a slickline.
 11. The apparatus of claim 10 whereinthe at least one FE sensor further comprises a plurality of sensors, theapparatus further comprising a device which positions at least one ofthe plurality of sensors at a different distance from a center of theborehole than another one of the plurality of sensors.